In-situ downhole measurement correction and control

ABSTRACT

A method includes providing a Bottom Hole Assembly (BHA) in a wellbore. The BHA includes a rotary steerable system and a downhole attitude correction and control system. The downhole correction and control system includes a first sensor set, the sensors of the first sensor set positioned near ferromagnetic components of a drill string and a second sensor set, the sensors of the second sensor set positioned further from the ferromagnetic components of the drill string than the sensors of the first sensor set. Corrupted data from the first sensor set and reference data from the second sensor set is obtained, the corrupted data including cross-axis magnetometer and accelerometer measurements. The method additionally includes correcting the corrupted sensor data to form corrected sensor measurements and calculating an estimated azimuth from the corrected sensor measurements. The method further includes steering the rotary steerable system based on the estimated azimuth.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation application of U.S. non-provisionalapplication Ser. No. 17/129,535 filed Dec. 21, 2020, which is acontinuation application of U.S. non-provisional application Ser. No.16/416,185 filed May 18, 2019, which claims priority from U.S.provisional application No. 62/673,320, filed May 18, 2018, each ofwhich is incorporated by reference herein in its entirety.

TECHNICAL FIELD/FIELD OF THE DISCLOSURE

The present disclosure relates to the establishment of orientation andcontrol of a downhole tool.

BACKGROUND OF THE DISCLOSURE

Knowledge of wellbore position is useful for the development ofsubsurface oil & gas deposits. Accurate knowledge of the position of awellbore at a measured depth, including inclination and azimuth of thewellbore, may be used to determine the geometric target location of, forexample, a hydrocarbon bearing formation of interest. Additionally,directional borehole drilling typically relies on one or moredirectional devices such as bent subs and rotary steering systems todirect the course of the wellbore. The angle between the referencedirection of the directional device and an external reference directionis referred to as the toolface angle, and may determine the direction ofdeviation of the wellbore as the wellbore is drilled. During directionaldrilling, the placement of the borehole is typically compared with thedesired path, and a toolface angle and other drilling parameters areselected to advance the borehole and correct the wellbore towards thedesired path. Measurement of toolface, inclination and azimuth thus maybe a component for borehole steering and placement. Additionally, when asteerable system such as a rotary steering system is used down-hole todirect the wellbore towards the desired path, changes in the selectedtoolface angle are typically sent from the surface to the down-holesystem by downlinking and sending an encoded message via one or moretelemetry channels, such as wired pipe, mud pump rate modulation, bypassof some of the drilling fluid through a bypass valve, drill stringrotation modulation, or electromagnetic excitation of the drill stringand surrounding formation. These downlink methods typically take asignificant amount of time and may disrupt drilling of the wellbore.

Downhole sensors, such as downhole sensors for measurement whiledrilling (MWD), logging while drilling (LWD) and other measurementmethods may be used for determining wellbore position. Certain sensorsmay be affected by downhole conditions or by the operation or proximatelocation of other components of the drill string. For example,magnetometers may be affected by ferromagnetic components of the drillstring such as a drill bit. Traditionally, such interactions may limitthe locations at which downhole sensors may be positioned along thedrill string or prevent the downhole sensors from being placed at apreferred location nearer to the drill bit.

SUMMARY

The present disclosure includes a method. The method includes providinga Bottom Hole Assembly (BHA) positioned in a wellbore. The BHA includesa rotary steerable system and a downhole attitude correction and controlsystem. The downhole correction and control system includes a firstsensor set having sensors, the sensors of the first sensor setpositioned near ferromagnetic components of a drill string and a secondsensor set having sensors, the sensors of the second sensor setpositioned further from the ferromagnetic components of the drill stringthan the sensors of the first sensor set. The downhole correction andcontrol system also includes a RSS controller, the RSS controlleroperatively coupled to and adapted to receive measurements from thefirst and second sensor sets, the controller in data communication withthe rotary steerable system. The method also includes obtainingcorrupted data from the first sensor set and reference data from thesecond sensor set, the corrupted data including along-hole andcross-axis magnetometer and accelerometer measurements. In addition, themethod includes depth aligning the corrupted sensor data and thereference data and calculating twist misalignment between the cross-axismagnetometer and accelerometer measurements of the corrupted sensor datato obtain a bias estimate. The method further includes calculating anestimated z axis magnetic scale factor and bias of the first sensor setand calculating a cross-axis magnetic scale factor of the corruptedsensor data. The method additionally includes correcting the corruptedsensor data to form corrected sensor measurements and calculating anestimated azimuth from the corrected sensor measurements. The methodfurther includes steering the rotary steerable system based on theestimated azimuth.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 depicts an overview of a drilling operation utilizing a drillstring incorporating downhole sensors consistent with at least oneembodiment of the present disclosure.

FIG. 2 depicts a drill string consistent with at least one embodiment ofthe present disclosure positioned in a wellbore.

FIG. 3 depicts a schematic view of a downhole attitude correction andcontrol system consistent with at least one embodiment of the presentdisclosure.

FIG. 4 depicts a process flow diagram of an attitude correctionoperation consistent with at least one embodiment of the presentdisclosure.

FIG. 5 depicts a schematic view of a steering operation of an RSSconsistent with at least one embodiment of the present disclosure.

FIG. 6 depicts a schematic view of a steering operation of and RSSconsistent with at least one embodiment of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various embodiments and/or configurations discussed.

FIG. 1 depicts an overview of a drilling operation in which wellbore 5is formed from surface 10 into formation 15 using drill string 20. Drillstring 20 may be made up of multiple tubular members coupled end-to-endto extend into wellbore 5. Drill string 20 may include bottom holeassembly (BHA) 25 positioned at a lower end of drill string 20. BHA 25may include one or more downhole tools used for forming or measuring oneor more aspects of wellbore 5 and formation 15 while BHA 25 ispositioned in wellbore 5. In some embodiments, for example and withoutlimitation, BHA 25 may include drill bit 30 used to form wellbore 5. Insome embodiments, BHA 25 may include downhole motor 35. Downhole motor35 may be used to rotate drill bit 30 during certain drilling operationssuch as sliding mode drilling operations. Downhole motor 35 may, forexample and without limitation, be a mud motor, turbine motor, orelectric motor. In some embodiments, BHA 25 may include one or moresensor packages including, for example and without limitation, azimuthalgamma tool 39. In some embodiments, BHA 25 may include survey tool 41.Survey tool 41 may be positioned at a distance from drill bit 30 on BHA25. In some embodiments, survey tool 41 may include one or more sensorsand controllers, as discussed further below, and may includenon-magnetic components such as, for example and without limitation,non-magnetic housing 42. In some embodiments, BHA 25 may include one ormore telemetry systems for communicating with surface equipment. In somesuch embodiments, BHA 25 may include mud pulser 43. In some embodiments,BHA 25 may include one or more power supplies 44, which may includebatteries for providing electric power to components of BHA 25. In someembodiments, BHA 25 may include a steering system for guiding theformation of wellbore 5 including, for example and without limitation,rotary steerable system (RSS) 45. RSS 45 may be used for a directionaldrilling operation. In some embodiments, RSS 45 may include one or moresteering members such as pads 50, which may be used to exert a forceagainst wellbore 5 to alter the direction of propagation of wellbore 5.In such an embodiment, the direction in which RSS 45 steers thepropagation of wellbore 5 is referred to as the toolface of RSS 45. Insome embodiments, RSS 45 may include non-rotating sleeve 55 positionedabout a rotating portion of RSS 45. Non-rotating sleeve 55 may bepositioned such that while drill string 20 is rotated, non-rotatingsleeve 55 does not rotate or rotates at a slow rate relative to wellbore5. In some embodiments, RSS 45 may include turbine generator 46 to, forexample and without limitation, provide electric power to RSS 45. Insome embodiments, RSS 45 may include RSS sensor package 47. RSS sensorpackage 47 may include one or more sensors and controllers as discussedfurther herein below.

In some embodiments, drill string 20 may include downhole attitudecorrection and control system 100. Downhole attitude correction andcontrol system 100 may include two or more sensor sets positioned atdifferent locations along drill string 20, referred to herein as firstsensor set 101 a and second sensor set 101 b. Although described withrespect to two sensor sets, the methods described in the presentapplication may be applied to any number of sensor sets. In someembodiments, each of first sensor set 101 a and second sensor set 101 bmay include one or more accelerometers and magnetometers such astriaxial accelerometers and triaxial magnetometers. In some embodiments,each of first sensor set 101 a and second sensor set 101 b may includeadditional sensors including, for example and without limitation,gyroscopes. In some embodiments, first sensor set 101 a may bepositioned at a location along drill string 20 such that the readings ofone or more sensors of first sensor set 101 a are interfered with bycomponents of drill string 20 such as drill bit 30. For example, in someembodiments, first sensor set 101 a may be part of RSS sensor package47. Second sensor set 101 b may be positioned at a location along drillstring 20 at which the readings of second sensor set 101 b are notexpected to be affected by other components of drill string 20. Forexample, in some embodiments, second sensor set 101 b may be part ofsurvey tool 41. In some such embodiments, first sensor set 101 a may bepositioned nearer to ferromagnetic components of drill string 20 suchas, for example and without limitation, drill bit 30, RSS 45, pads 50,non-rotating sleeve 55, turbine generator 46, or other components of BHA25 than second sensor set 101 b. Such sources of interference mayinclude hard and soft iron components that may cause apparent bias andscale factor errors for a magnetometer of first sensor set 101 apositioned nearby. Second sensor set 101 b may, in such an embodiment,be placed at a location on drill string 20 further uphole where lessmagnetic interference from components of drill string 20 is expected asshown in FIGS. 1 and 2 . In some embodiments, as discussed above, surveytool 41 may be positioned in non-magnetic housing 42. In someembodiments, first sensor set 101 a and second sensor set 101 b may bepositioned at a known separation distance apart along drill string 20and may be aligned within a known maximum bend angle, defined as theangle between the along-hole axis of wellbore 5 at first sensor set 101a and the along-hole axis of wellbore 5 at second sensor set 101 b. Asdiscussed further below, the twist angle between first sensor set 101 aand second sensor set 101 b, defined as the angle about the along-holeaxis of wellbore 5 between first sensor set 101 a and second sensor set101 b, may not need to be known and may change.

In some embodiments, each of first sensor set 101 a and second sensorset 101 b may be connected to a corresponding first sensor controller102 a and second sensor controller 102 b. In some embodiments, firstsensor controller 102 a may be part of RSS sensor package 47 and secondsensor controller 102 b may be part of survey tool 41. First sensorcontroller 102 a and second sensor controller 102 b may, among otheroperations, take and record measurements from the respective firstsensor set 101 a and second sensor set 101 b. In some embodiments,downhole attitude correction and control system 100 may include RSScontroller 103 included with drill string 20. In some embodiments, RSScontroller 103 may be part of RSS 45 and may include first sensor set101 a. In some embodiments, downhole attitude correction and controlsystem 100 may include MP controller 104. MP controller 104 mayperiodically request and receive measurements of second sensor set 101 bfrom survey tool 41. MP controller 104 may then transfer themeasurements of second sensor set 101 b to RSS controller 103. Each offirst sensor controller 102 a, second sensor controller 102 b, RSScontroller 103, and MP controller 104 may be interconnected, such as bya data bus and therefore able to communicate measurements, instructions,and other data between the controllers. For the purposes of thisdisclosure, RSS controller 103 is described; however operationsdescribed herein below may be distributed between one or more additionalcontrollers. In some embodiments, as depicted in FIG. 3 , RSS controller103 may be operatively coupled to and adapted to receive measurementsfrom first sensor set 101 a and second sensor set 101 b. In someembodiments, RSS controller 103 may include processor 105 adapted toperform computer program instructions according to methods includingthose described herein below. In some embodiments, processor 105 may be,for example and without limitation, a microprocessor, microcontroller,digital signal processor, ASIC, FPGA, or CPLD. In some embodiments, RSScontroller 103 may include storage memory 107 that may be used to, forexample and without limitation, store measurements received from firstsensor set 101 a and second sensor set 101 b as well as any otherinformation provided to RSS controller 103. In some embodiments, RSScontroller 103 may include one or more communications systems 109 toallow communication between RSS controller 103 and other components ofdrill string 20 such as survey tool 41, first sensor controller 102 a,and second sensor controller 102 b, or other systems positioned at thesurface through telemetry apparatus 111. Communication systems 109 mayinclude, for example and without limitation, one or more of wiredcommunication, wireless electromagnetic communication, or wirelessacoustic communication systems. In some embodiments, RSS controller 103may be adapted to communicate with or control RSS 45. In such anembodiment, RSS controller 103 may provide instructions to RSS 45 to,for example and without limitation, control the direction of drilling ofwellbore 5 by drill string 20 during a drilling operation.

In some embodiments, RSS controller 103 may include instructions on anon-transitory computer-readable media to process the measurementsreceived from first sensor set 101 a and second sensor set 101 b todetermine the orientation of BHA 25 within wellbore 5 including, forexample and without limitation, the inclination, azimuth, and toolfaceof drill string 20 within wellbore 5. In some embodiments, first sensorcontroller 102 a may take measurements from first sensor set 101 a andsecond sensor controller 102 b may take measurements from second sensorset 101 b within wellbore 5 as drill string 20 is moved within wellbore5, such as during a drilling operation. In some embodiments,measurements may be taken while drill string 20 is moving withinwellbore 5. The measurements may be received and stored by RSScontroller 103. Because first sensor set 101 a and second sensor set 101b are spaced apart along drill string 20, the measurements of firstsensor set 101 a and second sensor set 101 b may make measurements atthe same point along wellbore 5 at different times. However, becausefirst sensor set 101 a is positioned proximate a source of interferenceon drill string 20, the measurements made by first sensor set 101 a maybe less accurate than the measurements made by second sensor set 101 b.

In some embodiments, RSS controller 103 may combine measurements fromfirst sensor set 101 a and second sensor set 101 b to, for example andwithout limitation, estimate measurement errors on the measurements fromfirst sensor set 101 a, second sensor set 101 b, or both. In some suchembodiments, the measurements may be corrected for the identifiedmeasurement errors and may be used to estimate the orientation of BHA 25including, for example and without limitation, the attitude includingthe inclination and azimuth of RSS 45.

FIG. 4 depicts a process flow diagram of a downhole measurementcorrection and control operation 200 consistent with at least onenon-limiting embodiment of the present disclosure. In FIG. 4 , firstsensor set 101 a and second sensor set 101 b each includes sensors tomeasure cross axis and Z-axis (aligned with the longitudinal axis ofdrill string 20) components of the magnetic and gravitation fields.Different embodiments of the present disclosure may make use ofdifferent sensors to accomplish these measurements. For example andwithout limitation, in some embodiments, a z-axis gyro and a cantedmagnetometer and accelerometer could estimate these fields. In otherembodiments, each of first sensor set 101 a and second sensor set 101 bmay include two magnetometers oriented such that the sensitive axes aresubstantially not parallel and two accelerometers oriented such that thesensitive axes are substantially not parallel. In other embodiments,each of first sensor set 101 a and second sensor set 101 b may includeat least one magnetometer aligned with the longitudinal axis of drillstring 20 (Z-axis magnetometer), at least one magnetometer alignedsubstantially perpendicular to the longitudinal axis of drill string 20(cross-axis magnetometer), an accelerometer aligned with thelongitudinal axis of drill string 20 (Z-axis accelerometer), and atleast one accelerometer aligned substantially perpendicular to thelongitudinal axis of drill string 20 (cross-axis accelerometer).

In some embodiments, downhole measurement correction and controloperation 200 may include obtaining measurements from first sensor set101 a and second sensor set 101 b (201). In some embodiments, thesensors of first sensor set 101 a and second sensor set 101 b may besampled while drill string 20 is moving within wellbore 5, includingduring rotation and longitudinal translation during a drillingoperation. In certain embodiments, first sensor set 101 a and secondsensor set 101 b may be sampled while drill string 20 is rotating or notrotating and while drill string 20 is at constant depth or whilechanging in depth. In some embodiments, sensors of first sensor set 101a and second sensor set 101 b may be sampled at, for example and withoutlimitation, between 50 Hz and 1 KHz. In some embodiments, one or morecontrollers such as first sensor controller 102 a and second sensorcontroller 102 b may initially correct the measurements by applyingcalibration parameters to the sensor readings (202). For example, insome embodiments, calibrated scale factors, bias, and misalignments maybe applied to the respective sensor readings. Such calibrated scalefactors, biases, and misalignments may be determined by calibrationexperimentation undertaken before first sensor set 101 a and secondsensor set 101 b are used in wellbore 5. In some embodiments, suchcalibrated scale factors, biases, and misalignments may be determinedin-situ. In some embodiments, a combination of calibration parametersdetermined prior to sensor sets 101 a and 101 b being in the wellboreand calibration parameters identified in-situ, may be used to correctthe measurements. In some embodiments, where the measurements areobtained during rotation of drill string 20, accelerometer andmagnetometer readings may be phase aligned to, for example and withoutlimitation, reduce or remove phase error of the magnetometer readingsdue to eddy-current effects caused by conductive materials of drillstring 20 rotating in the earth's magnetic field. In some embodiments,magnetic interference may likewise be subtracted from the magnetometerreadings due to experimentally determined interference of non-rotatingsleeve 55 or RSS 45. In some embodiments, such magnetic interference maybe determined in-situ. In some embodiments, one or more sensors may beused to determine the relative orientation between first sensor set 101a and non-rotating sleeve 55 such as an encoder or tick-sensor. Asdiscussed above, the measurements may then be received by RSS controller103. In some embodiments, second sensor controller 102 b may performfewer operations than first sensor controller 102 a. In some suchembodiments, second sensor controller 102 b may correct scale factorbias and misalignment, and may provide an average of the correctedsamples to RSS controller 103. In some embodiments, RSS controller 103may perform one or more of these operations.

In some embodiments, the in-situ determination of magnetic interferencedue to non-rotating sleeve 55, utilizes measurements of the corruptedmagnetic field sensed by sensor set 101 a as well as the relativeorientation of non-rotating sleeve 55. Variations in the cross axis andalong axis field that are synchronous with the rotation of non-rotatingsleeve 55 can be identified using the method described in U.S. patentapplication Ser. No. 15/676,463, the entirety of which is herebyincorporated by reference. The synchronous variations in the magnitudeof the cross axis magnetic field, the total magnetic field, as well asthe individual components of the magnetic field, sensed by sensor set101 a, can be used to estimate the magnetic interference when the actualinclination and azimuth of sensor set 101 a is varying. In someembodiments, estimations of the inclination and azimuth of sensor set101 a can be utilized to help separate out the variations that are dueto the magnetic interference of non-rotating sleeve 55 from thevariations that occur due to changes in orientation of sensor set 101 a.

In some embodiments, a state estimator, such as a Kalman Filter, may beutilized for estimating the magnetic interference that is due tonon-rotating sleeve 55. Using the methods described in U.S. patentapplication Ser. No. 15/676,463, rotating measurements from sensor set101 a may be processed to obtain estimates of the magnetic fieldcomponents in a different frame of reference. The orientation ofnon-rotating sleeve 55 may also be calculated in this same frame ofreference. In some embodiments, one of the axes, herein called the Zaxis, of said frame of reference is aligned with the nominal rotationalaxis of sensor set 101 a, which is typically the same, or nearly thesame rotational axis of non-rotating sleeve 55 as well as the alongdirection of the proximate wellbore. In some embodiments, the magneticfield components sensed by sensor set 101 a due to the magneticinterference of non-rotating sleeve 55 can thus be modelled as afunction of the angle θ of non-rotating sleeve 55 about this Z axis. Insome embodiments, the modelling function for the cross-axis magneticinterference may be sinusoidal:

B _(INT) =I*cos(θ)Q*sin(−θ)

Where I and Q are the portion of the interference aligned with the X andY axes respectively. The magnetic field components sensed by sensor set101 a are a combination of non-rotating sleeve 55 magnetic interferencecomponents, earth's magnetic field components, and other magneticinterference components that are not of interest. The cross axismagnetic field components sensed by sensor set 101 a can thus be modeledas:

B _(I) =I*cos(θ)+B _(cross)*cos(θ_(MTF))+η_(I)

B _(Q) =Q*sin(−θ)+B _(cross)*sin(−θ_(MTF))+η_(Q)

Where η_(I) and η_(Q) are the magnetic interference components and noisethat are not of interest, and θ_(MTF) is the magnetic toolface of theframe of reference, which is the negative rotation angle of the frame ofreference about the Z axis that would cause the X axis to align with thecross-axis projection of earth's magnetic field vector. In someembodiments, the state to be estimated by the state estimator may be:

$x = \begin{bmatrix}I \\Q \\I_{bias} \\Q_{bias}\end{bmatrix}$

where I_(bias) and Q_(bias) are intended to track the combination of theearth's magnetic field and the bias of the magnetometer sensors ofsensor set 101 a that are present in the cross axis components.In some embodiments in which a Kalman Filter is used as the stateestimator, the measurement model may be:

$H = \begin{bmatrix}1 & 0 & 1 & 0 \\0 & 1 & 0 & 1\end{bmatrix}$

Resulting in measurements of the true state:

$z_{k} = {{H + \eta} = \begin{bmatrix}B_{I} \\B_{Q}\end{bmatrix}}$

where

is the true state and η is measurement noise. In some embodiments, uponobtaining a new measurement of θ, a Kalman state transition matrix iscalculated so as to propagated forward the I and Q estimates:

$\begin{bmatrix}I \\Q \\I_{bias} \\Q_{bias}\end{bmatrix}_{k} = {\begin{bmatrix}{\cos\left( {\theta_{k} - \theta_{k - 1}} \right)} & {- {\sin\left( {\theta_{k} - \theta_{k - 1}} \right)}} & 0 & 0 \\{\sin\left( {\theta_{k} - \theta_{k - 1}} \right)} & {\cos\left( {\theta_{k} - \theta_{k - 1}} \right)} & 0 & 0 \\0 & 0 & 1 & 0 \\0 & 0 & 0 & 1\end{bmatrix}\begin{bmatrix}I \\Q \\I_{bias} \\Q_{bias}\end{bmatrix}}_{k - 1}$

Where the subscript k corresponds to the sample number. In someembodiments, the Kalman Filter correction, as well as growth of theerror covariance matrix, may not be performed for each new measurementθ, but only when the new θ is sufficiently different from the value of θthat was used for the prior correction. Other criteria may also be usedto determine when to perform the correction step and growth of the errorcovariance matrix, such as whether or not the new θ measurement isdeemed an outlier based on estimations of rotation rate and uncertaintyof rotation rate of non-rotating sleeve 55. In some embodiments,estimations of the change in inclination and azimuth may also be used toupdate the state estimates of I_(bias) and Q_(bias). Such estimations ofinclination and azimuth may be performed separately, as additionalstates in the same state estimator, or as calculations based onadditional states in the same estimator, as would be obvious to thoseskilled in the art. The estimates of I and Q may then be used tosubtract out the magnetic interference from the estimates of the crossaxis components of the magnetic field sensed by sensor set 101 a, andcorrected estimations of Mtf can be made. In some embodiments, similarestimations and corrections can be made for the Z axis magneticinterference that varies as a function of θ.

In some embodiments, RSS controller 103 may periodically calculate adifference (delta) between magnetic and gravity toolfaces (Mtf-HsTF),cross-axis acceleration (Across), Z-axis acceleration (Az), cross-axismagnetic field (Bcross), z-axis magnetic field (Bz), and inclination ofdrill string 20 at the locations of wellbore 5 at which first sensor set101 a and second sensor set 101 b are located based on the respectivemeasurements of first sensor set 101 a and second sensor set 101 b. Insome embodiments, inclination may be calculated as the four-quadrantinverse tangent of Across and Az according to:

Inc=a tan 2(Across, −Az)

In some embodiments, the attitude may be determined at, for example andwithout limitation, once per second. Such an attitude determination maybe undertaken according to the methods described by U.S. patentapplication Ser. No. 15/676,463, the entirety of which is herebyincorporated by reference in its entirety.

In some embodiments, RSS controller 103 may calculate at predeterminedintervals a sliding average and variance of MTF-HsTF, Across, Az,Bcross, Bz, and inclination for the measurements of first sensor set 101a or for each of the measurements of first sensor set 101 a and secondsensor set 101 b. A sliding or windowed average calculation may becomputed as the sum of samples divided by the number of samples takenover the specified time period. Likewise, a sliding or windowed variancemay be computed by calculating the variance of the samples taken overthe specified time period. These computations may be performedincrementally rather than re-calculated at each new sample or by use ofinfinite impulse response filters or other iterative techniques toreduce computational and or memory requirements on the processing systemused to perform the calculations, i.e. RSS controller 103. In someembodiments, the sliding averages and variances may be calculated, forexample and without limitation, across a time period between 1 secondand 30 seconds. In some embodiments, the sliding averages and variancesmay be computed once per second.

In some embodiments, RSS controller 103 may calculate at predeterminedintervals a mean of the calculated sliding averages and sum of squaresof the calculated sliding averages of the measurements from first sensorset 101 a and second sensor set 101 b. In some embodiments, the meansand sums of squares may be calculated once a minute. In someembodiments, the means and sums of squares may be stored in data buffersfor the measurements of first sensor set 101 a and the measurements ofsecond sensor set 101 b in storage memory 107. For the purposes of thisdisclosure, the data associated with the means and sums of squares offirst sensor set 101 a defines corrupted sensor data and the dataassociated with the means and sums of squares of second sensor set 101 bdefines a reference sensor data. In some embodiments, depending on theamount of storage space available, RSS controller 103 may store sensordata buffers corresponding to thirty minutes of data.

In some embodiments, RSS controller 103 may depth align the corruptedsensor data and reference sensor data (203). Because first sensor set101 a and second sensor set 101 b are separated by an along-holedistance, the samples in time may be time shifted for the same depths asdrill string 20 moves through wellbore 5. The data buffers are depthaligned such that measurements of the corrupted sensor data buffer andreference sensor data buffer are aligned with respect to the positionwithin wellbore 5 represented by the data of the data buffers, such thatthe reference sensor data buffer is taken at the same depth and sameattitude as the corresponding measurement of the corrupted sensor databuffer taken at the same depth and same attitude.

In some embodiments, the corrupted sensor data buffer and referencesensor data buffer may be depth aligned by searching for matchingmeasurements or patterns in the measurements taken by first sensor set101 a and second sensor set 101 b. In some embodiments, inclination maybe used to depth align the data buffers. In some embodiments,measurements taken by other sensors of first sensor set 101 a and secondsensor set 101 b including, for example and without limitation, gammareadings, sonic readings, or resistivity, may be used to depth align thedata buffers. In some embodiments, one or more such measurements may beused in combination to depth align the data buffers.

In some embodiments, first sensor set 101 a and second sensor set 101 bmay not be sampled simultaneously, at the same sample rate, or at thesame sample intervals, and may be sampled, processed, and averaged byseparate computing systems of RSS controller 103. In such an embodiment,RSS controller 103 may interpolate samples of first sensor set 101 a andsecond sensor set 101 b when depth aligning the data buffers. Suchinterpolation may be used whenever the depth alignment resolutionbetween the samples of first sensor set 101 a and second sensor set 101b is insufficient with the effective sample rate of the data being usedfor depth alignment.

In some embodiments, such as where there is insufficient change in themeasurements of first sensor set 101 a and second sensor set 101 b toallow reliable pattern matching between the data buffers, a nominal timelag based on expected rate of penetration (ROP) may be used to depthalign the measurements. Such an embodiment may be used, for example andwithout limitation, where wellbore 5 is straight or near straight andthe attitude of first sensor set 101 a and second sensor set 101 b aresubstantially the same.

In some embodiments, RSS controller 103 may identify and calculate anytwist misalignment between the cross-axis magnetometer and accelerometermeasurements of the corrupted sensor data using the reference sensordata (205). In some such embodiments, the twist misalignment may becalculated as the difference between the reference and corrupted sensordata Mtf-HsTF according to:

deltaMtfHtfbiasEstimate

=deltaMtfHtfbiasEstimate*(1−wtAdaptDeltaMtfHtf)

+wtAdaptDeltaMtfHtf

*((Mtf_(corrupted)−HsTF_(corrupted))−(Mtf_(reference)−HsTF_(reference)))

RSS controller 103 may then calculate the adaptation weighting to beapplied to deltaMtfHtfbiasEstimate. In some embodiments, an adaptiveinfinite impulse response (IIR) filter may be used. In some embodiments,the adaptation weighting may be calculated based on one or more of theinclination of the reference sensor data, the inclination differencebetween the reference sensor data and the corrupted sensor data, theangle between the Z-axis of drill string 20 and the magnetic fieldvector of the Earth (Bangle), and the difference between Bz readings ofthe reference sensor data and corrupted sensor data. The adaptationweighting may, for example and without limitation, set the adaptationspeed of downhole measurement correction and control operation 200. Insome embodiments, the adaption weighting may be calculated according to:

wtAdaptDeltaMtfHtf

=max(0, min(1, AdaptScalar*wtRefinc*wtBangle*wtDeltalnc

*wtDeltaBz))

Where incDiffNormFactor=3.0 (reasonable values depend on the possiblephysical bend between the reference sensor set and the corrupted sensorset); bzDiffNormFactor=1000.0 nanoTesla (reasonable values would be 100nT up to 5000 nT); AdaptScalar=1.0 (this is a configurable parameter,but 1.0 is a reasonable value, however any positive value could beused); wtRefInc=sin(reference sensor data inclination);wtBangle=sin(bAngle); wtDeltaInc=1-min(1, abs(reference sensor datainclination−corrupted sensor data inclination)+(standard deviation ofcorrupted sensor data inclination))/incDiffNormFactor); andwtDeltaBz=1-min(1, abs(ref Bz−(corrected Bz from corrupted sensordata))/bzDiffNormFactor.

In some embodiments, RSS controller 103 may update one or both of theestimated z axis magnetic scale factor and bias of first sensor set 101a (209). In some embodiments, both estimated z axis magnetic scalefactor and bias of first sensor set 101 a may be updated when drillstring 20 has changed attitude, such as where the Bz of the referencesensor data and the Bz of the corrupted sensor data are sufficientlydifferent from the mean of the respective Bz values used in the previousiteration to be considered a new orientation. An example of the criteriathat may be used for determining whether or not the new sensor data islikely to correspond to a new orientation is as follows:

|Bz _(corrupted)−

_(corrupted)|>minBzDelta

|Bz _(reference)−

_(reference)|>minBzDelta

where minBzDelta is a configured threshold, 200 nT being a reasonabledefault value,

_(corrupted) is mean of the corrupted Bz values used in the previousiteration,

_(reference) is the mean of the reference Bz values used in the previousiteration, Bz_(corrupted) is the new measurement of Bz from thecorrupted sensor set, and Bz_(reference) is the new measurement of Bzfrom the reference sensor set. When both of the above equations aretrue, it may be concluded that the new measurements of Bz correspond toa sufficiently different orientation such that the new measurements willimprove the estimates of z axis magnetic scale factor and bias. Thevariance of the Bz of both the reference sensor data and corruptedsensor data may also be taken into account in the determination ofwhether or not the drill string has changed attitude sufficiently. Insome such embodiments, RSS controller 103 may use a least squaresmethod, such as linear least squares, iteratively reweighted leastsquares, or any other type of regression analysis, to solve for z-axismagnetic scale factor and bias of first sensor set 101 a. Theindependent variables in such embodiments are Bz of the corrupted sensordata and a constant. The dependent variable is the estimate oftheoretical Bz, which is referred to as Bz_(reference). When linearleast squares is utilized to solve for z-axis magnetic scale factor andbias of first sensor set 101 a, the set of linear equations can beformulated as shown in the following equation:

${\begin{bmatrix}{{Bz}_{corrupted}\lbrack 1\rbrack} & 1 \\{{Bz}_{corrupted}\lbrack 2\rbrack} & 1 \\ \vdots & \vdots \\{{Bz}_{corrupted}\lbrack N\rbrack} & 1\end{bmatrix}\begin{bmatrix}{scale}_{Bz} \\{bias}_{Bz}\end{bmatrix}} = \begin{bmatrix}{{Bz}_{reference}\lbrack 1\rbrack} \\{{Bz}_{reference}\lbrack 2\rbrack} \\ \vdots \\{{Bz}_{reference}\lbrack N\rbrack}\end{bmatrix}$

where Bz_(reference)[k] is the k^(th) estimate of the theoretical Bz,Bz_(corrupted)[k] is the k^(th) mean value of Bz from the corruptedsensor set 101 a, scale_(B)z is the Bz scale factor being solved for,and bias_(Bz) is the bias being solved for. In some embodiments,Bz_(reference) may be obtained from z axis measurements from thereference second sensor data set 101 b. In some embodiments,Bz_(reference) may be obtained from the cross axis measurements of thecorrupted sensor data (Bcross_(corrupted)), the estimate for cross-axisscale factor (Bcross_(Scale)), and a known, or estimated, total magneticfield strength (Btotal_(reference)) according to:

Bz _(reference)=√{square root over((Btotal_(reference))²−(Bcross_(Scale) *Bcross_(corrupted))²)}

In some embodiments, Bz_(reference) may be obtained from both of theembodiments described above or from any other method that may result inan estimate of Bz along with a measure of the uncertainty of Bz. In someembodiments, Btotal_(reference) may be calculated from reference sensorset 101 b.

In some embodiments, the known or estimated differences in orientationbetween the depth aligned reading of Bz_(corrupted) and Bz_(reference),may be used to calculate a correction to either Bz_(corrupted) orBz_(reference). In some embodiments, such a correction may also utilizeknowledge and/or measurements/estimations of the local magnetic field(Btotal and Bdip), local gravitational field (Atotal), azimuth of sensorset 101 a, azimuth of sensors set 101 b, or any combination thereof. Onepossible purpose of this correction is to account for the differences inorientation between the readings from sensor set 101 a and sensor set101 b. The differences in orientation may be due, for example only andnot limited to, inexact depth alignment and/or quantization of thereadings to be aligned. In some embodiments, an assumption may be madethat the difference in orientation is mainly an inclination difference,such as when drilling the curve of a wellbore. In such embodiments, thecorrection may be calculated according to:

Bz _(Diff)=sin(Inc_(corrupted))*cos(Azi_(corrupted))*B_(north)+cos(Inc_(corrupted))*B_(down)−sin(Inc_(reference))*cos(Azi_(corrupted))*B_(north)+cos(Inc_(reference))*B _(down)

Where Inc_(corrupted) is the inclination of sensor set 101 a,Inc_(reference) is the inclination of second sensor set 101 b,Azi_(corrupted) is the azimuth of sensor set 101 a, Azi_(reference) isthe azimuth of second sensor set 101 b, and B_(north) and B_(down) arecalculated according to:

B _(north) =B _(Total)*cos(B _(Dip))

B _(down) =B _(Total)*sin(B _(Dip))

Where B_(Total) is the magnitude of earth's magnetic field, and B_(Dip)is the angle of the earth's magnetic field with respect to horizontal.The calculated value for Bz_(Diff) at each iteration may then be eithersubtracted from Bz_(corrupted) added to Bz_(reference) before beingincluded in the set of linear equations.

In some embodiments, instead of augmenting the set of linear equationsat each iteration, the covariance matrix of the independent variablesand the cross-covariance between the independent variables and thedependent variables may be stored on RSS controller 103 for iterativeupdates to, for example and without limitation, save processor time andmemory usage. In such an embodiment, the components stored can be usedto solve for scale factor and bias according to the following, which isreferred to as the normal equation:

[ corrupted 2 corrupted corrupted 1 ] [ scale Bz bias Bz ] = [covariance estimate ]

Where the hat symbol indicates estimations of the correspondingvariable.

In some embodiments, updates to the components of the covariance matrixand the cross-covariance vector may be weighted based on estimations ofthe current solutions uncertainty and estimations of the uncertainty ofthe new set of measurements. In some embodiments, the uncertainty of thenew set of measurements may be calculated based on estimations of theuncertainty of the corrupted Bz measurement from first sensor set 101 a,and estimations of the uncertainty of the new estimates of Bz. In someembodiments, in which the new estimate of Bz is from second sensor set101 b, the estimation of the uncertainty of the new set of measurementsmay also be based on differences in inclination between the corruptedfirst sensor set 101 a and the reference second sensor set 101 b,differences in Bz between the corrupted first sensor set 101 a and thereference second sensor set 101 b, the variances of inclination from thecorrupted first sensor set 101 a , and the variances of inclination fromthe reference second sensor set 101 b. In some embodiments, the estimateof the uncertainty of the new set of measurements may be calculatedaccording to:

σ_(input) ²=σ_(Bz) _(corrupted) ²+σ_(Bz) _(reference)²+WtIncorrupted*σ_(inc) _(corrupted) ²+WtIncReference*σ_(inc)_(reference) ²+WtDeltaInc*(Inc_(corrupted)−Inc_(reference))²

Where WtIncCorrupted, WtIncReference, and WtDeltaInc are set to positivevalues in order to provide similar magnitudes for the inclinationvariances as the Bz variances, as well as provide the ability to adjustthe relative weighting between the various uncertainties. Values forWtIncCorrupted, WtIncReference, and WtDeltaInc may be any positivenumber, with reasonable values being between 10 and 1000, and 100 beingused in some embodiments.

In some embodiments, in which Bzreference is calculate based onknowledge of the local magnetic field and the corrupted Bz measurementfrom first sensor set 101 a, the estimation of the uncertainty of thenew set of measurements may be calculated according to:

$\sigma_{Input}^{2} = {\sigma_{{Bz}_{corrupted}}^{2} + {\frac{1}{{Bz}_{reference}^{2}}*\left( {{{Btotal}_{reference}^{2}*\sigma_{{Btotal}_{reference}}^{2}} + {{Bcross}_{corrupted}^{2}*\sigma_{{Bcross}_{corrupted}}^{2}}} \right)}}$

The weighting to be applied to the new set of measurements may becalculated according to:

${inputWeighting} = \frac{\sigma_{Estimate}^{2}}{\sigma_{Estimate}^{2} + \sigma_{Input}^{2}}$

The weighting may be used to update the components of the covariancematrix and the cross-covariance vector according to:

_(corrupted) ²=

_(corrupted) ²*(1−inputWeighting)+inputWeighting*Bz _(corrupted) ²

_(corrupted)=

_(corrupted)*(1−inputWeighting)+inputWeighting*Bz _(corrupted)

_(covariance)=

_(covariance)*(1−inputWeighting)+inputWeighting*Bz _(corrupted)*Bz_(estimate)

_(reference)=

_(reference)*(1−inputWeighting)+inputWeighting*Bz _(reference)

Additionally, a quantification of the uncertainty, here denoted byσ_(Estimate) ², of the adapted covariance matrix and thecross-covariance vector, may be updated according to:

σ_(Estimate) ²=(1−inputWeighting)²*σ_(Estimate)²+inputWeighting²*σ_(input) ²

In some embodiments, such as where drill string 20 is not changingattitude sufficiently from a prior iteration of the above calculations,Bz bias alone may be estimated. In some such embodiments, Bz bias may beestimated using an adaptive Kalman filter to track the differencebetween the Bz of the corrupted sensor data (corrected for scale factoronly) and the Bz of the reference sensor data.

In some embodiments, the adaptive Kalman filter may be configured toestimate a single constant. The measurement covariance, R, and processcovariance, Q, may be set based on, for example and without limitation,one minute estimates of variance for the reference sensor data Bz andthe corrupted sensor data Bz. One or both of these parameters may, insome embodiments, be adjusted in-situ. In some embodiments, stateestimate covariance may also be selected such that the adaptation rateis coordinated with the adaptation rate, inputWeighting. The variance ofthe current estimate for the scale factor and bias solution,σ_(Estimate) ², may be used to calculate an upper bound for the statecovariance, P, of the adaptive Kalman filter according to:

P=min(P, σ _(Estimate) ² *Pfactor)

where Pfactor is a configurable variable, with 3 being a typical value,and reasonable values being in the range of 1 to 5.

In some embodiments, reasonable bounds of the angle between theorientation of sensor set 101 a and sensor set 101 b are eitherpredetermined or calculated in-situ. The reasonable bounds fororientation differences between the two sensor sets may be utilized tocalculate reasonable bounds for the expected difference between thereference sensor set 101 b readings and the corrected readings fromsensor set 101 a. In some embodiments, the inclination and azimuthcalculated from corrected sensor set 101 a readings may be used incombination with the readings from second sensor set 101 b to calculatemaximum and minimum thresholds for the differences between the correctedreadings of sensor set 101 a and sensor set 101 b. In some suchembodiments, the maximum and minimum thresholds may be calculatedaccording to:

maxAziBend=√{square root over (max(0,coneAngle²−(Inc_(reference)−Inc_(corrected))²))}

Azi_(left)=Azi_(corrected)−maxAziBend

Azi_(right)=Azi_(corrected)−maxAziBend

Bz _(center)=sin(Azi_(corrected))*cos(Azi_(corrected))*B_(north)+cos(Azi_(corrected))*B _(down)

Bz _(left)=sin(Inc_(reference))*B_(north)*cos(Azi_(left))+cos(Inc_(reference))*B _(down)

Bz _(right)=sin(Inc_(reference))*B_(north)*cos(Azi_(right))+cos(Inc_(reference))*B _(down)

DeltaBz _(min)=min(Bz _(left) −Bz _(center) , Bz _(right) −Bz _(center))

DeltaBz _(max)=max(Bz _(left) −Bz _(center) , Bz _(right) −Bz _(center))

Where B_(north) and B_(down) are the horizontal and vertical componentsof local gravity, coneAngle is the maximum angle determined to bepossible between sensor set 101 a and 101 b, and Azi_(corrected) is thecalculated azimuth from the corrected sensor readings from sensor set101 a. DeltaBz_(min) and DeltaBz_(max) can then be used to determine themaximum and minimum threshold values for Bz_(reference) according to:

MaxBz _(reference) =Bz _(reference)+DeltaBz _(max) +Bz _(margin)

MinBz _(reference) =Bz _(reference)−DeltaBz _(min) −Bz _(margin)

Where Bz_(margin) is a configuration parameter, with a value of 50 nTbeing reasonable for some embodiments, and reasonable ranges beingbetween 10 nT and 1000 nT. Similar bounds may be calculated for otherreadings, such as B_(cross) and deltaMtfHtf. In some embodiments, theadaptation rates for the adapted parameters may be adjusted when one ormore readings do not lie within their respective calculated bounds. Insome embodiments, when this occurs, real-time notifications may be sentto the surface and/or to the closed loop controller indicating theidentified condition. In some embodiments, any of the details or resultsof an in-situ compensation and control operation as described herein maybe sent to the surface by any telemetry method known in the art. In someembodiments, one or more states or parameters of the in-situcompensation and control operation may be adjusted by commands sent fromthe surface by any telemetry method known in the art.

In some embodiments, RSS controller 103 may calculate the cross axismagnetic scale factor of the corrupted sensor data using the depthaligned reference sensor data and may adapt the estimated cross axisscale factor of the corrupted sensor data towards the estimated value(211). In some such embodiments, RSS controller 103 may use an IIRfilter of the depth aligned Bcross of the reference sensor data as theestimate. In some embodiments, the estimated cross axis scale factor ofthe corrupted sensor data may only be adapted if the corrupted Bcross isabove a threshold, such as, for example and without limitation, a valuebetween 50 and 5000 nT.

In some embodiments, RSS controller 103 may use the updated estimates ofz axis scale factor and bias and cross axis scale factor of thecorrupted sensor data to correct the measurements from first sensor set101 a (213).

In some embodiments, RSS controller 103 may calculate an updatedestimated azimuth based on at least one of the corrected measurementsfrom first sensor set 101 a (215). In some embodiments, the updatedestimated azimuth may be calculated according to:

${Azimuth} = {a{\tan\left( \frac{\sin({deltaMtfHtfCorrected})}{\begin{matrix}{{\frac{BzCorrected}{BcrossCorrected}*\sin({inclination})} +} \\{\cos({inclination})*\cos({deltaMtfHtfCorrected})}\end{matrix}} \right)}}$

where

deltaMtfHtfCorrected=MTF−HsTF+deltaMtfHtfBiasEstimate

BzCorrected=Bz*BzScale+BzBias

BcrossCorrected=Bcross*BcrossScale

Other embodiments may calculate an updated estimated azimuth using otherformulas that utilize at least 1 of the corrected measurements ofdeltaMtfHtfCorrected, BzCorrected, or BcrossCorrected.

Thus, inaccuracies in determining the attitude of RSS 45 at the locationof first sensor set 101 a caused by the effects of magnetic interferenceproximate to first sensor set 101 a may be reduced, and a more accurateazimuth may be determined.

In some embodiments, RSS controller 103 may calculate a change inestimated azimuth due to an update to the corrections of Bz, Bcross anddeltaMtfHtf, thus separating the change in estimated azimuth due toupdates to corrections from the change in azimuth due to estimatedphysical attitude change. In some embodiments, RSS controller 103 usesboth the updated estimated azimuth and the updated change in estimatedazimuth due to updates to corrections to adjust control of RSS 45 asdescribed below.

In some embodiments, RSS controller 103 may be used to control RSS 45,and may use the estimated azimuth or the estimated azimuth and thechange in estimated azimuth due to updates to corrections to provideinstructions to RSS 45 and thereby steer the propagation of wellbore 5(217). In some such embodiments, a target plane control mode may beemployed. Referring now to FIG. 5 , in one embodiment of a target planecontrol mode, a control plane 501 may be defined by a starting attitude503 and a target attitude 505 to drill towards and hold. In someembodiments, both the starting attitude 503 and target attitude 505 maybe sent from the surface via a downlink message. In other embodiments,only the target attitude 505 may be sent from the surface via downlinkand the starting attitude 503 determined by the estimated attitude ofthe tool at the time the target attitude downlink was received. Definingcontrol plane 501 based on the downlinked target attitude 505 andestimated attitude at the time the downlink is received may reducedownlink transmission time and reduce wellbore tortuosity due tosteering forces applied to correct for the attitude error between adownlink specified starting attitude and the estimated attitude at thetime the downlink is received. In some embodiments, control plane 501may be defined by its normal vector 507 which may be calculatedaccording to:

controlPlaneNormal=startAttitude×targetAttitude

where x denotes the vector cross product and startAttitude andtargetAttitude are the starting attitude 503 and target attitude 505vectors in North, East, Down earth coordinates and may be calculatedaccording to:

${{startAttitude} = \begin{bmatrix}{{\sin({startInclination})}{\cos({startAzimuth})}} \\{{\sin({startInclination})}{\sin({startAzimuth})}} \\{\cos({startInclination})}\end{bmatrix}}{{targetAttitude} = \begin{bmatrix}{{\sin({targetInclination})}{\cos({targetAzimuth})}} \\{{\sin({targetInclination})}{\sin({targetAzimuth})}} \\{\cos({targetInclination})}\end{bmatrix}}$

Once a control plane is defined, RSS controller 103 may separatesteering forces into two orthogonal components, a to-plane steeringforce 509 in the direction normal to control plane 501 and a to-targetsteering force 511 parallel to control plane 501 and in the direction oftarget attitude 505.

In some embodiments, RSS controller 103 may operate autonomouslydown-hole on the to-plane steering force 509 by employing a single axisattitude controller with the error input 513 being the angle between theestimated attitude 515 obtained from the estimated inclination andazimuth and control plane 501 and the output being the to-plane steeringforce 509 applied by RSS 45 normal to control plane 501. In suchembodiments, the attitude control law applied may, for example andwithout limitation, be determined by a PID, PID with leaky integrator,PID with leaky integrator and integrator dead zone, parameter adaptive,non-parametric adaptive, model reference adaptive, or other control lawknown in the art. In some such embodiments, the to-plane controllererror input 513 may be calculated according to:

${errorAngleToPlane} = {{\cos^{- 1}\left( \frac{{controlPlaneNormal} \cdot {estimatedAttitude}}{{{controlPlaneNormal}}{{estimatedAttitude}}} \right)} - {90{^\circ}}}$

where · denotes the dot product, ∥ ∥ denotes the vector magnitude or L2norm, and estimatedAttitude is the estimated attitude 515 vector whichcan be calculated from the updated estimated azimuth and inclinationaccording to:

${estimatedAttitude} = \begin{bmatrix}{{\sin({inclination})}{\cos({Azimuth})}} \\{{\sin({inclination})}{\sin({Azimuth})}} \\{\cos({inclination})}\end{bmatrix}$

In some embodiments, RSS controller 103 may adjust the control plane inresponse to an update to corrections of Bz, Bcross and deltaMtfHtf. Insome such embodiments, RSS controller 103 may mathematically rotate thecontrol plane about the target attitude vector so that the error angleto the plane does not include any error due to the updated corrections,and thus avoid steering force corrections due to the correction updateswhich may undesirably introduce increased wellbore tortuosity. In somesuch embodiments, the control plane rotation angle about the targetvector may be calculated according to:

${rotationAngle} = \frac{{errorAngleToPlanePrior} - {errorAngleToPlane}}{\sin({errorAngleInPlanePrior})}$

where errorAngleToPlane is the error angle to the control plane withupdated estimated azimuth with the most recent corrections,errorAngleToPlanePrior is the error angle to the control plane with theupdated estimated azimuth calculated with the prior corrections anderrorAngleInPlanePrior is the angle between the target attitude and theprojection of the attitude vector obtained using the updated estimatedazimuth calculated with the prior corrections onto the control plane,all of which may be calculated according to:

${{errorAngleInPlanePrior} = {\cos^{- 1}\left( \frac{\begin{matrix}\left\lbrack {{controlPlaneNormal} \times} \right. \\{\left. \left( {{estimatedAttitudePrior} \times {controlPlaneNormal}} \right) \right\rbrack \cdot} \\{targetAttitude}\end{matrix}}{\begin{matrix}{{{controlPlaneNormal} \times}} \\{\left( {{estimatedAttitudePrior} \times {controlPlaneNormal}} \right)} \\{{targetAttitude}}\end{matrix}} \right)}}{{errorAngleToPlanePrior} = {{\cos^{- 1}\left( \frac{{controlPlaneNormal} \cdot {estimatedAttitudePrior}}{{{controlPlaneNormal}}{{estimatedAttitudePrior}}} \right)} - {90{^\circ}}}}$

where estimatedAttitudePrior is the attitude vector calculated from theestimated Azimuth using the prior deltailMtfHtfCorrected, BzCorrectedand B_(cross)Corrected. In such embodiments, the control plane may berotated about rotationAngle according to the following calculations:

controlPlaneNormal_(i) =RM*controlPlaneNormal_(i−1)

where controlPlaneNormal_(i) is the rotated control plane used in thepresent iteration and controlPlaneNormal_(i−1) is the non-rotatedcontrol plane normal from the prior iteration and RM is the rotationmatrix which may be calculated according to:

RM=cos(rotationAngle)*1+sin(rotationAngle)*[targetAttitude]_(x)+(1−cos(rotationAngle))*targetAttitude*targetAttitude^(T)

where I is the identity matrix, [targetAttitude]_(x) denotes the crossproduct matrix of the target attitude vector and targetAttitude^(T)denotes the transpose of the target attitude vector. The cross productmatrix of the target attitude vector may be constructed according to:

[targetAttitude]_(×)= $\begin{bmatrix}0 & {- {targetAttitude}_{D}} & {targetAttitude}_{E} \\{targetAttitude}_{D} & 0 & {- {targetAttitude}_{N}} \\{- {targetAttitude}_{E}} & {targetAttitude}_{N} & 0\end{bmatrix}$

where targetAttitude_(N), targetAttitude_(E), and targetAttitude_(D)correspond to the North, East and Down components of the target attitudevector described above. In some such embodiments, RSS controller 103 maycalculate a 3D angle difference between the estimated attitude utilizingthe corrections from the current update and prior update and rotate thecontrol plane only when the 3D angle difference exceeds a particularvalue so that smaller corrections resulting in less wellbore tortuosityare immediately accounted for which may result in reduced 3D wellborepath error. In such embodiments, the 3D angle difference may be between0.1 deg and 0.5 deg. In other embodiments, RSS controller 103 may adjustthe control plane in response to an update to corrections of Bz, Bcrossand deltaMtfHtf by applying the updated corrections to the uncorrectedBz, Bcross and deltaMtfHtf stored at the time the target attitudedownlink was received, calculating an updated starting attitude from thecorrected Bz, Bcross and deltaMtfHtf values, and calculating an updatedcontrol plane based on the updated starting attitude.

In a further aspect of an embodiment of a target plane control mode,to-target steering force 511 applied by RSS 45 in the direction parallelto the control plane in the direction of the target attitude control theturn rate towards the target attitude. In some embodiments, theto-target steering force 511 may be determined by an operator and sentmanually via downlink from the surface to RSS controller 103. In otherembodiments, turn rate per along-hole depth within the target plane maybe specified by the operator and used as the set point in a turn ratecontroller which regulates to-target steering force 511 to achieve adesired turn rate towards the target attitude. In some embodiments of aturn rate controller, the desired turn rate may be downlinked fromsurface to RSS controller 103 which may operate autonomously down-holeto adjust to-target steering force 511 applied by RSS 45 parallel to thecontrol plane to achieve the desired turn rate towards the targetattitude. In such an embodiment, RSS controller 103 may estimate theturn rate towards the target, for example and without limitation, byprojecting the estimated attitudes from first sensor set 101 a andsecond sensor set 101 b onto the control plane and dividing the anglebetween the projections by the distance between first sensor set 101 aand second sensor set 101 b. RSS controller 103 may then compare theestimated turn rate to the desired turn rate and adjust to-targetsteering force 511 applied by RSS 45 parallel to the control plane toachieve the desired turn rate. Since wellbore 5 will only changeattitude as drilling progresses, RSS controller 103 may calculate anupdated estimate of turn rate towards the target only after detectingthat drilling has occurred for a minimum time period, where the minimumtime period may be between 30 sec and 3 min. Methods for detectingdrilling may include, for example and without limitation, comparingdown-hole measured lateral vibration, axial vibration, weight on bit,torque on bit, angular acceleration or any combination thereof topre-defined thresholds. In some embodiments, the range of to-targetsteering force 511 autonomously adjusted by RSS controller 103 may belimited. In some embodiments the force may be limited to a pre-definedrange, for example and without limitation, +−15% about a nominal forcetheoretically expected to achieve the desired turn rate. In embodimentsincorporating autonomous down-hole turn rate control, communication ofdata between the surface and RSS controller 103 may be minimized,allowing, for example and without limitation, more rapid controlcorrections and more accurate placement of wellbore 5 by RSS 45. Inother embodiments, the turn rate controller may be implemented in asurface computing system. In such embodiments, the surface computingsystem may estimate turn rate periodically by dividing the angledifference between the estimated wellbore attitude transmitted bydownhole attitude correction and control system 100 through telemetryapparatus 111 obtained at two different depths by the difference indepths. The surface computing system may then compare the estimated turnrate to the desired turn rate and calculate an adjustment to to-targetsteering force 511 to achieve the desired turn rate which may betransmitted via downlink to RSS controller 103. In such an embodiment,the downlink may be triggered automatically or the operator may beprompted to perform the downlink manually. In other embodiments, surfaceestimated turn rate may periodically be downlinked and RSS controller103 may merge downhole and surface determined estimates of turn rate viaa Kalman filter or other similar optimal or adaptive estimation methodto obtain the estimate of turn rate used by the turn rate controller. Insome embodiments, a model of the expected turn rate as a function ofsteer force may be used by the turn rate controller, whether locatedup-hole or downhole, to improve the accuracy of the adjustment of thesteer force to achieve the desired turn rate. In some such embodiments,the model may be non-parametric and may be adapted based on pastmeasurement of turn rate per steer force. In other such embodiments, themodel may be parametric and may be dependent, for example and withoutlimitation, on parameters such as weight on bit, RSS 45 attitude, bitcondition, the turn rate of wellbore 5 directly above RSS 45. In otherembodiments of a turn rate controller, the surface system mayperiodically downlink the along-hole depth of drill bit 30 measured atthe surface by use of a draw-works encoder or other depth measurementdevice to RSS controller 103 which may then calculate the turn rate asthe difference in angle between the estimated wellbore attitudes dividedby the difference in depths.

When RSS 45 nears the target attitude, RSS controller 103 mayautomatically exit the target plane control mode described above andenter a target hold mode. Determining when RSS 45 is near the targetattitude may be accomplished by projecting the tool attitude vector ontothe control plane and determining if the error angle between theprojection and the target attitude is below a threshold where thethreshold may be, for example and without limitation, a value between0.1 deg and 10 deg. Now referring to FIG. 6 , in one exemplaryembodiment of a target hold mode, RSS controller 103 may project thetarget attitude vector 505 onto the cross-borehole plane 601 of RSS 45periodically. The period may be 1 sec but could reasonably be between0.1 sec and 10 sec depending on processing capability available andexpected ROP. At each periodic update of the target hold mode, theestimated attitude vector with respect to earth North, East and Downcoordinates may be determined from the estimated inclination and azimuthas [sin(Inclination)*cos(Azimuth); sin(Inclination)*sin(Azimuth);cos(Inclination)]. The target attitude vector in NED earth coordinates,which may be determined in like fashion, may then be vector projected(603) onto the cross-borehole plane 601 to determine a desired steeringdirection. In one embodiment, the cross-borehole plane 601 may beseparated into to orthogonal components and separate controllersemploying a PID or other similar control law may operate on theirrespective components of the projected target vector to determine theorthogonal components of a correcting steering force applied by RSS 45required to maintain the target attitude.

For both the target plane control mode and target hold control modesdescribed above, RSS controller 103 may define the cross-borehole planeY axis 605 and cross-borehole plane X axis 607 with respect to any ofthe earth's fixed fields in order to reference the steering direction tothe desired field. For example, when defining a steering direction withrespect to the earth's gravity field, the Y axis may be defined to bein-line with the projection of the earth's gravity field onto thecross-borehole plane of the system and the X axis mutually orthogonal tothe Y and Z axis where the Z axis is defined down the along-boreholeaxis. When defining a steering direction with respect to the earth'smagnetic field, the Y axis may be defined to be in-line with theprojection of the earth's magnetic field onto the cross-borehole planeof the system and the X axis mutually orthogonal to the Y and Z axiswhere the Z axis is defined down the along-borehole axis. When defininga steering direction with respect to the earth's rotation vector (truenorth), the Y axis may be defined to be in-line with the projection ofthe earth's rotation vector onto the cross-borehole plane of the systemand the X axis mutually orthogonal to the Y and Z axis where the Z axisis defined down the along-borehole axis. In some embodiments a targetsteering direction may be determined by a weighted sum of the gravityand magnetic referenced directions where the weights are determined by afunction of inclination or a function of the measured cross-boreholegravity and/or magnetic field magnitudes. In other embodiments, weightsmay be determined as a function of estimates of uncertainty of thegravity, magnetic or gyro measurements used to determine the direction.

In some embodiments, a target steering direction and force may,alternatively, be sent from the surface to the downhole system and usedby RSS controller 103 to set the force applied by RSS 45 to propagatethe path of wellbore 5 in the desired direction. In some suchembodiments, the steering direction and force may be determined manuallyby an operator by using the estimated tool attitude as described aboveand along-hole measured depth to determine an error of the wellbore 5from the desired wellbore path. In other embodiments, the steeringdirection and force may be determined automatically by a surfacecomputing system by using the estimated tool attitude and along-holemeasured depth to determine an error of the wellbore 5 from the desiredwellbore path. In such embodiments, the determined steering directionand force may automatically trigger a downlink or, alternatively, berecommended to the operator. In other embodiments, the steering forceapplied in only the horizontal axis of the down-hole controller may besent from the surface to the downhole system and may be determined andsent in a manner similar to the target steering direction and force.

In some embodiments, RSS controller 103 may incorporate one or moreautomated course correction sequences which may further reduce thenumber and frequency of downlinks required to correct wellbore 5 to thedesired well path. In some such embodiments where RSS controller 103 isoperating according to target hold control mode described above at thestart of the course correction operation, RSS controller 103 may executean automated course correction sequence in response to a coursecorrection downlink sent from the surface system. In such embodiments,when a course correction downlink is received, RSS controller 103 maystore the original target attitude in memory and enter target planecontrol mode with a temporary target attitude and direct RSS 45 to applya correcting steer force parallel to the control plane and force normalto the plane as previously described until the temporary target attitudeis reached. Once the temporary target attitude is reached, RSScontroller 103 may then automatically set the target attitude back tothe original target attitude and continue drilling towards the targetattitude using target plane control mode as previously described usingthe correcting steer force. In some embodiments, the course correctiondownlink may specify the temporary target attitude directly. In otherembodiments, the course correction downlink may specify a steeringdirection and angle relative to the current estimate of tool attitudefrom which the temporary target attitude is calculated by RSS controller103 which may reduce the number of possibilities and thereforetransmission time compared to specifying the temporary target attitudedirectly. In some embodiments, the course correcting downlink mayspecify the correcting steer force directly. In other embodiments, thecourse correcting downlink may specify a DLS which RSS controller 103uses to determine the correcting steer force parallel to the plane in anautomated manner using any of the previously described methods.

In another automated course correction sequence embodiment, where RSScontroller 103 is operating according to target plane control mode atthe start of the course correction operation, RSS controller 103 mayapply a course correcting adjustment to the control plane by rotatingthe control plane about the vector lying in the original control planeand perpendicular to the target attitude vector by a specified angle. Insuch an embodiment, a downlink from surface may be sent specifying therotation angle and correction force to be applied normal to the rotatedcontrol plane. RSS controller 103 may then proceed in target planecontrol correction mode, directing RSS 45 to apply the previouslyindicated force parallel to the plane and the newly specified correctionforce normal to the plane until the tool attitude is determined to besubstantially one the plane. Once RSS controller 103 determines that thetool attitude is substantially on the rotated control plane, theoriginal control plane is restored and RSS controller 103 continues intarget plane control correction mode, directing RSS 45 to apply thepreviously indicated force parallel to the restored original controlplane and the correction force normal to the restored original controlplane until the tool attitude is substantially on the original controlplane. Once RSS controller 103 determines that the tool attitude issubstantially on the original control plane, RSS controller 103 exitstarget plane control correction mode and re-enters target plane controlmode with the original parameters.

For the automated course correcting sequence methods described above, insome embodiments the parameters of the course correcting downlink aredetermined by an operator and the downlink is sent manually. In otherembodiments, the parameters of the course correcting downlink aredetermined automatically by a surface computing system to achieve thedesired displacement of the wellbore to substantially align the wellborewith the desired well path. In such embodiments, the determinedparameters may be recommended to the operator or sent via anautomatically triggered downlink. In other embodiments, along-hole depthmay be periodically downlinked to RSS controller 103 which may thendetermine the parameters of the course correcting sequence down-hole.

The foregoing outlines features of several embodiments so that a personof ordinary skill in the art may better understand the aspects of thepresent disclosure. Such features may be replaced by any one of numerousequivalent alternatives, only some of which are disclosed herein. One ofordinary skill in the art should appreciate that they may readily usethe present disclosure as a basis for designing or modifying otherprocesses and structures for carrying out the same purposes and/orachieving the same advantages of the embodiments introduced herein. Oneof ordinary skill in the art should also realize that such equivalentconstructions do not depart from the scope of the present disclosure andthat they may make various changes, substitutions, and alterationsherein without departing from the spirit and scope of the presentdisclosure.

1. A method comprising: providing a Bottom Hole Assembly (BHA)positioned in a wellbore, the BHA comprising: a rotary steerable system;and a RSS controller for controlling the rotary steerable system, theRSS controller having at least one single axis attitude controlleradapted to measure attitude and compute a to-plane steering force, ato-target steering force, or a combination thereof: defining a controlplane containing a target attitude for the rotary steerable system todrill towards and at least one other attitude that is not parallel withthe target attitude; separating a steering force into two orthogonalcomponents, the two steering forces consisting of: the to-plane steeringforce in the direction normal to the control plane; and the to-targetsteering force in the direction of the target attitude parallel with thecontrol plane; and causing the RSS to control the trajectory of awellbore being drilled using the to-plane steering force and theto-target steering force.
 2. The method of claim 1, wherein the to-planesteering force or the to-target steering force is determined using aPID, a PID with leaky integrator, a PID with integrator dead zone, a PIDwith leaky integrator and integrator dead zone, a parameter adaptive, anon-parametric adaptive, a model reference adaptive, or a combinationthereof.
 3. The method of claim 1, wherein the to-target steering forceis downlinked from a surface of the earth.
 4. The method of claim 1,wherein the to-plane steering force is downlinked from a surface of theearth.
 5. The method of claim 1, wherein the turn rate controllerdetermines the to-target steering force.
 6. The method of claim 1,wherein the to-target steering force defines a turn rate per along-holedepth.
 7. The method of claim 6 further comprising specifying a desiredturn rate.
 8. The method of claim 7 further comprising adjusting theto-target steering force applied by the RSS to achieve the desired turnrate by comparing the desired turn rate with an estimated turn rate. 9.The method of claim 8, wherein the desired turn rate is downlinked froma surface of the earth.
 10. The method of claim 8 further comprisingdetermining the estimated turn rate from at least two attitudemeasurements calculated at different along-hole depths.
 11. The methodof claim 10 further comprising estimating turn rate by projectingattitude measurements from at least one pair of at least two attitudemeasurements onto the control plane and dividing the angle between theprojections by an along-hole distanced between each of the least twoattitude measurements.
 12. The method of claim 11 further comprisingcalculating the at least two attitude measurements from separate sensorslocated at different relative along-hole depths in the BHA.
 13. Themethod of claim 11 further comprising calculating the at least twoattitude measurements at different times corresponding to the BHA beingin at least two different along-hole depths.
 14. The method of claim 8,wherein the estimated turn rate is determined by the RSS controllerdown-hole.
 15. The method of claim 14, wherein an along-hole depth isdownlinked to the RSS controller and the RSS controller uses thealong-hole depth to estimate the turn rate per depth.
 16. The method ofclaim 8, wherein the estimated turn rate is determined at a surface ofthe earth and downlinked to the RSS controller.
 17. The method of claim8 further comprising using a model of the expected turn rate as afunction of steer force.
 18. The method of claim 17, wherein the modelof the expected turn rate as a function of steer force is non-parametric19. The method of claim 17, wherein the model of expected turn rate as afunction of steer force is adapted based on past measurements of turnrate per steer force.
 20. The method of claim 18, wherein the model ofexpected turn rate as a function of steer force is parametric.
 21. Themethod of claim 20, wherein the model of the expected turn rate includesparameters and the parameters include weight on bit, RSS attitude, bitcondition, or turn rate of wellbore directly above the rotary steerablesystem.
 22. The method of claim 8, wherein an along-hole depth of adrill bit is downlinked to the RSS controller, and the RSS controllerutilizes the depth to calculate an estimated turn rate.
 23. The methodof claim 1 further comprising executing an automated course correctionsequence using the RSS controller.
 24. The method of claim 23, whereinthe automated course correction sequence is triggered by a downlink froma surface of the earth.
 25. The method of claim 23, wherein theautomated course correction sequence starts by entering a target controlplane mode with a temporary target attitude.
 26. The method of claim 25,wherein an original target attitude is restored after reaching thetemporary target attitude.
 27. The method of claim 25, wherein thetemporary target attitude is downlinked to the RSS controller from asurface of the earth.
 28. The method of claim 27, wherein a steeringdirection and an angle relative to a current estimate of an RSS attitudeis downlinked to the RSS controller from the surface, and the temporarytarget attitude is calculated by the RSS controller based on thedownlinked steering direction and relative angle.
 29. The method ofclaim 23, wherein the RSS controller is in a target plane control mode,and the automated course correction sequence starts by rotating thecontrol plane about a vector in the control plane by a specified angleto form a rotated control plane.
 30. The method of claim 29, wherein thevector rotated about in the control plane is a target vector.
 31. Themethod of claim 30, wherein the control plane is restored once therotary steerable system is in the rotated control plane.
 32. A methodcomprising: providing a Bottom Hole Assembly (BHA) positioned in awellbore, the BHA comprising: a rotary steerable system; and a RSScontroller for controlling the rotary steerable system, the RSScontroller having a target hold mode, the target hold mode comprising:determining the cross-borehole plane of the rotary steerable system;projecting the target attitude vector onto a cross-borehole plane of therotary steerable system; and using the projected target attitude vectorto determine a desired steering direction.
 33. The method of claim 32,wherein the cross-borehole plane is separated into orthogonalcomponents, and separate controllers employing a PID operates on theirrespective components of a projected target vector to determine theorthogonal components of a correcting steering force applied to therotary steerable system to maintain a target attitude.
 34. The method ofclaim 33, wherein the RSS controller further includes a target planecontrol mode.
 35. The method of claim 34, wherein the RSS controllertransitions from a target plane control mode into target hold mode whenthe rotary steerable attitude is detected to be within a defined angleof the target attitude.